Without limiting the scope of the present invention, its background is described with reference to steam injection, as an example.
It is common practice in the production of hydrocarbons from a reservoir to use a variety of techniques to maximize recovery. Typically, in the initial stage of hydrocarbon production from a reservoir, energy stored in the reservoir displaces the hydrocarbon fluids from the reservoir into the wellbore and up to surface. Whether gasdrive, waterdrive, gravity drainage or the like, the reservoir pressure is sufficiently higher than the bottomhole pressure inside the wellbore such that the natural pressure difference drives the hydrocarbon fluids toward the well and up to surface. It has been found, however, that reservoir pressure declines as a result of hydrocarbon production. This decline in reservoir pressure results in a reduced differential pressure between the bottomhole pressure and the reservoir pressure which in turn causes production rates to decline.
In certain reservoirs, production rates can be maintained at economic levels using secondary recovery techniques that stabilize reservoir pressure, displace hydrocarbons toward the wellbore or both. For example, secondary recovery may involve injecting a fluid, such as water or gas, into the reservoir from one or more injection wells that are in fluid communication with the production wells. Specifically, gas may be injected into the gas cap to enhance reservoir pressure and/or water may be injected into the production zone to displace oil from the reservoir. Once secondary recovery techniques reach the end of their economic viability, the productive life of certain reservoirs may be further extended using enhanced oil recovery techniques. For example, enhanced oil recovery operations may involve chemical flooding, miscible displacement and thermal recovery.
One method of thermal recovery involves the use of steam which may be generated at surface and injected into the reservoir through one or more injection wells. In this operation, the steam enters the reservoir and heats up the crude oil to reduce its viscosity. In addition, the hot water that condenses from the steam helps to drive oil toward producing wells. It has been found, however, that steam regulation may be difficult, particularly when the steam is being injected into multiple zones of interest from a single injection well. In this scenario, the annular area between the tubular and each zone of interest is typically isolated with packers. Steam is injected from the tubular into each zone of interest through one or more nozzles located in the tubing string at each zone. Due to differences in the pressure and/or permeability of the zones as well as pressure and thermal losses in the tubular string, the amount of steam entering each zone is difficult to control. One way to assure steam injection at each zone is to establish a critical flow regime through each of the nozzles.
Critical flow of a compressible fluid through a nozzle is achieved when the velocity through the throat of the nozzle is equal to the sound speed of the fluid at local fluid conditions. Once sonic velocity is reached, the velocity and therefore the flow rate of the fluid through the nozzle cannot increase regardless of changes in downstream conditions. Accordingly, regardless of the differences in annular pressure at each zone, as long as critical flow is maintained at each nozzle, the amount of steam entering each zone is known. It has been found, however, that to ensure the critical flow of steam through typical steam injection nozzles, the annulus to tubing pressure ratio must be maintained below about 0.6. To overcome this limitation, attempts have been made to use nozzles having downstream diffuser portions to increase the annulus to tubing pressure ratio that can maintain critical flow. These installations, however, have involved the use of tubular strings having side pockets which significantly increase tubing complexity and reduce fluid flow capacity.
Therefore, a need has arisen for an apparatus and method for extending the productive life of a reservoir by improving steam injection recovery techniques. A need has also arisen for such an apparatus and method that is operable to maintain critical flow of steam into a zone of interest at annulus to tubing pressure ratios over 0.56. Further, a need has arisen for such an apparatus and method that is operable to inject steam at a controlled flow rate into multiple zones of interest from a single injection wellbore.